Natural gas gathering compressor facilities built using traditional methods use separate pieces of equipment connected with lengths of pipe which must all be sized for anticipated station growth. The growth plans change often, affected by the dynamic nature of drilling plans, differing well production flows, and unknown longevity/decrease of flows from different wells. Using an optimistic approach, a station will be built with oversized pipe and equipment anticipating a target growth size. Until that size is reached, the extra cost of the larger initial infrastructure burdens the economics for the site. If a station outgrows its target size, then the current infrastructure must be re-built to handle the added site capacity—an expensive and often fatal economic blow to the expansion plans.
Traditional compressor facility designs are progressing into a mode where equipment modularization is perceived as a cost saving design and construction advantage. Previous modularization efforts, however, simply mimic the usual approach of using separate pieces of equipment connected with separate utility and process piping systems. This usually results in a large site with extensive site civil works, with lengthy and expensive construction schedules.
A compressor station is a facility which helps the transportation process of natural gas from one location to another. A gathering compressor station is used as a centralized location where several wells in an area send their flows. Though natural gas is considered “dry” as it passes through a pipeline, the raw gas from the wells is saturated with liquids in the form of hydrocarbons or water. This liquid condenses in the pipes leading to the compressor station and eventually flows into the station from planned pigging operations or as unplanned slugs of free liquids. Compressor stations typically include equipment such as slug catcher vessels, scrubbers, strainers or filter separators which remove liquids, dirt, particles, and other impurities from the natural gas; each piece of equipment has its own specific function that is distinguishable from the other pieces of equipment. The removed impurities from the gas are disposed as waste or sold if possible.
Previous Inlet Slug Catcher systems work by routing all incoming gas and liquid through a large steel vessel where the gas slows down enough for any liquids to fall to the bottom of the vessel. Additional mechanical methods such as demisters or vane packs are sometimes employed in the vessels to assist with liquid separation. Since the vessel size is limited by shipping dimensions (and weight), additional liquid storage space is often added; these storage spaces are commonly referred to as “finger skids”. From the temporary storage in the vessel and finger skids, the liquid is slowly drained into liquid pipes, known as liquid “headers”, that run throughout the facility. These pipe systems carry the gathered liquids to on-site storage tanks or processing systems. The liquid-free gas is then routed to the compressor suction via piping systems known as gas “headers”.
The inlet to a compressor station must be designed to the possible future size of the facility since it is generally intended to be a gas receipt point from multiple wells over a number of years. This process is always filled with compromise since the general industry mindset is to “build it once”, but with increasing size comes higher initial cost. Sizing the inlet system is usually a problematic issue. When sizing a gathering facility's inlet system, the Engineer needs to evaluate possible gas pressures and flow rates that could occur over time. The evaluation starts with identifying the possible mix of liquids and gases that comes up from a gas well. Usually the Producer (well owner) installs a steel vessel (free liquid separator) at the well location to separate the free liquid from the gas. If this equipment malfunctions or is not properly operated, some or all these free liquids can be sent with the gas to the compressor station. Even when well pad separation equipment is properly operated, the gas leaving the well pad is still saturated with liquids (analogous to a “fog”). The gas cools as it runs through underground piping to a compressor facility. When the “fog” cools it condenses, or “rains”, inside the pipe. To keep the pipe from filling with condensate over time, the pipeline Operators will run a “pig” (analogous to a rubber “squeegee”) through the line to push the liquids out of the pipe. This liquid ends up coming into the compressor station as a “slug” of liquid. Depending on the gas composition, frequency of the pigging, terrain “ups and downs”, the amount of gas flowing through the line, distance from the wells, and ambient conditions, the liquid volumes can vary. There are always unknown variables that can affect the amount of liquids coming into a station. One of the biggest unknowns is how much gas will end up flowing to the proposed station since higher gas flows carry more saturated liquids which in turn increase the condensate volumes. All these factors make the “one-time” initial sizing of compressor station inlet separation steel vessel (Slug Catcher) equipment a frustrating challenge.
Optionally, an inlet filter separator vessel could be used as part of the inlet system. If used, this piece of equipment is installed downstream of the Slug Catcher to trap any airborne solid particulates and aerosol liquids carried with the gas stream. The inlet filter separator generally has an internal impingement area to remove aerosol liquids from the inlet gas stream and a removable media filter to trap airborne solid particulates.
After traversing the inlet system, liquid-free gas then goes through a series of piping systems to the compressors. All these main artery lines throughout the facility are sized for a maximum flow at a given pressure. As previously mentioned, this sizing for future flow conditions is part educated guesswork tempered with an analysis balancing costs with the risk of under or oversizing the infrastructure. Once the gas lines reach the compressors, a branch line is routed to each machine. In the industry, compressors of different sizes and flow rate capacity are used, and even within an individual facility can differ, and each compressor size requires more or less flow, and the piping systems to and from each machine must be sized to the specific operating conditions for each machine.
The traditional, previously described inlet systems are typically designed to perform their functions for the entire compressor facility where there are multiple compressors. This leads to several common problems. For example, the inlet system must be designed to feed several compressors. However, due to the changing nature of natural gas drilling and production, it is unusual that all the compressors planned for any site are needed and installed with the initial facility build. Therefore, the installed size (or capacity) of an inlet system rarely matches the installed compression needs at any given site. Oversizing the infrastructure for planned expansion results in extra costs for the initial station build. The penalty for under-sizing the same infrastructure could be that future expansion needs are prohibitively expensive.